<PAGE>
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FORM 10-Q
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Quarterly Report under Section 13 or 15(d)
of the Securities Exchange Act of 1934
For Quarter Ended June 30, 1998
Commission File Number 1-3376-2
THE POTOMAC EDISON COMPANY
(Exact name of registrant as specified in its charter)
Maryland and Virginia 13-5323955
(State of Incorporation) (I.R.S. Employer Identification No.)
10435 Downsville Pike, Hagerstown, Maryland 21740-1766
Telephone Number - 301-790-3400
The registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months and (2) has been subject to such
filing requirements for the past 90 days.
At August 14, 1998, 22,385,000 shares of the Common Stock (no
par value) of the registrant were outstanding, all of which are
held by Allegheny Energy, Inc., the Company's parent.
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THE POTOMAC EDISON COMPANY
Form 10-Q for Quarter Ended June 30, 1998
Index
Page
No.
PART I--FINANCIAL INFORMATION:
Statement of income - Three and six months ended
June 30, 1998 and 1997 3
Balance sheet - June 30, 1998
and December 31, 1997 4
Statement of cash flows - Six months ended
June 30, 1998 and 1997 5
Notes to financial statements 6-9
Management's discussion and analysis of financial
condition and results of operations 10-20
PART II--OTHER INFORMATION 21
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THE POTOMAC EDISON COMPANY
Statement of Income
<TABLE>
<CAPTION>
Three Months Ended Six Months Ended
June 30 June 30
1998 1997 1998 1997
(Thousands of Dollars)
ELECTRIC OPERATING REVENUES:
<S> <C> <C> <C> <C>
Residential $ 65,932 $ 66,256 $ 156,261 $ 157,819
Commercial 38,797 34,367 76,488 71,863
Industrial 52,412 50,034 100,924 96,771
Wholesale and other, including affiliates 10,365 8,992 21,349 19,474
Bulk power transactions, net 10,013 5,218 14,195 11,168
Total Operating Revenues 177,519 164,867 369,217 357,095
OPERATING EXPENSES:
Operation:
Fuel 35,924 33,472 71,481 68,869
Purchased power and exchanges, net 29,518 32,047 65,443 69,644
Deferred power costs, net 5,655 (667) 5,688 (990)
Other 22,521 19,777 43,699 41,499
Maintenance 12,492 15,320 27,228 30,904
Depreciation 18,720 18,374 37,365 36,751
Taxes other than income taxes 12,155 12,756 25,064 24,930
Federal and state income taxes 10,498 6,894 25,591 21,532
Total Operating Expenses 147,483 137,973 301,559 293,139
Operating Income 30,036 26,894 67,658 63,956
OTHER INCOME AND DEDUCTIONS:
Allowance for other than borrowed funds
used during construction 18 317 215 724
Other income, net 2,346 3,174 4,562 5,781
Total Other Income and Deductions 2,364 3,491 4,777 6,505
Income Before Interest Charges 32,400 30,385 72,435 70,461
INTEREST CHARGES:
Interest on long-term debt 11,740 11,913 23,540 23,827
Other interest 367 451 951 1,203
Allowance for borrowed funds used during
construction (211) (355) (482) (668)
Total Interest Charges 11,896 12,009 24,009 24,362
NET INCOME $ 20,504 $ 18,376 $ 48,426 $ 46,099
</TABLE>
See accompanying notes to financial statements.
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THE POTOMAC EDISON COMPANY
Balance Sheet
<TABLE>
<CAPTION>
June 30, December 31,
1998 1997
ASSETS: (Thousands of Dollars)
Property, Plant, and Equipment:
<S> <C> <C>
At original cost, including $51,486,000
and $55,702,000 under construction $ 2,220,157 $ 2,196,262
Accumulated depreciation (894,300) (859,076)
1,325,857 1,337,186
Investments:
Allegheny Generating Company - common stock at equity 45,738 55,847
Other 487 529
46,225 56,376
Current Assets:
Cash 1,626 2,319
Accounts receivable:
Electric service, net of $1,978,000 and $1,683,000
uncollectible allowance 78,521 83,431
Affiliated and other 17,099 5,302
Notes receivable from affiliates 48,550 1,450
Materials and supplies - at average cost:
Operating and construction 23,863 23,715
Fuel 18,768 15,843
Prepaid taxes 13,187 15,052
Other 1,167 4,716
202,781 151,828
Deferred Charges:
Regulatory assets 77,058 80,651
Unamortized loss on reacquired debt 16,812 17,094
Other 17,972 17,512
111,842 115,257
Total Assets $ 1,686,705 $ 1,660,647
CAPITALIZATION AND LIABILITIES:
Capitalization:
Common stock $ 447,700 $ 447,700
Other paid-in capital 2,690 2,690
Retained earnings 259,875 239,391
710,265 689,781
Preferred stock 16,378 16,378
Long-term debt and QUIDS 628,202 627,012
1,354,845 1,333,171
Current Liabilities:
Long-term debt due within one year - 1,800
Accounts payable 25,176 29,125
Accounts payable to affiliates 29,087 19,929
Taxes accrued:
Federal and state income 262 2,106
Other 15,536 11,461
Interest accrued 9,211 9,487
Payrolls accrued - 6,353
Other 10,449 10,553
89,721 90,814
Deferred Credits and Other Liabilities:
Unamortized investment credit 20,532 21,470
Deferred income taxes 181,577 178,529
Regulatory liabilities 11,877 12,424
Other 28,153 24,239
242,139 236,662
Total Capitalization and Liabilities $ 1,686,705 $ 1,660,647
</TABLE>
See accompanying notes to financial statements.
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THE POTOMAC EDISON COMPANY
Statement of Cash Flows
<TABLE>
<CAPTION>
Six Months Ended
June 30
1998 1997
(Thousands of Dollars)
CASH FLOWS FROM OPERATIONS:
<S> <C> <C>
Net income $ 48,426 $ 46,099
Depreciation 37,365 36,751
Deferred investment credit and income taxes, net 2,045 4,424
Deferred power costs, net 5,688 (990)
Unconsolidated subsidiaries' dividends in excess of earnings 10,139 1,477
Allowance for other than borrowed funds used
during construction (215) (724)
Restructuring liability (1,187) (7,011)
Changes in certain current assets and
liabilities:
Accounts receivable, net (6,887) 6,113
Materials and supplies (3,073) (5,261)
Accounts payable 5,209 (13,126)
Taxes accrued 2,231 4,976
Other, net 2,336 5,424
102,077 78,152
CASH FLOWS FROM INVESTING:
Construction expenditures (less allowance for
equity funds used during construction) (26,927) (25,806)
CASH FLOWS FROM FINANCING:
Issuance of long-term debt 4,200 -
Retirement of long-term debt (5,000) (800)
Short-term debt, net - (7,497)
Notes receivable from affiliates (47,100) (34,650)
Dividends on capital stock:
Preferred stock (409) (409)
Common stock (27,534) (10,297)
(75,843) (53,653)
NET CHANGE IN CASH (693) (1,307)
Cash at January 1 2,319 1,444
Cash at June 30 $ 1,626 $ 137
SUPPLEMENTAL CASH FLOW INFORMATION:
Cash paid during the period for:
Interest (net of amount capitalized) $22,941 $24,268
Income taxes 25,973 16,620
</TABLE>
See accompanying notes to financial statements.
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THE POTOMAC EDISON COMPANY
Notes to Financial Statements
1. The Company's Notes to Financial Statements in its Annual
Report on Form 10-K for the year ended December 31, 1997
should be read with the accompanying financial statements and
the following notes. With the exception of the December 31,
1997 balance sheet in the aforementioned annual report on
Form 10-K, the accompanying financial statements appearing on
pages 3 through 5 and these notes to financial statements are
unaudited. In the opinion of the Company, such financial
statements together with these notes contain all adjustments
necessary to present fairly the Company's financial position
as of June 30, 1998, the results of operations for the three
and six months ended June 30, 1998 and 1997, and cash flows
for the six months ended June 30, 1998 and 1997.
2. The Statement of Income reflects the results of past
operations and is not intended as any representation as to
future results. For purposes of the Balance Sheet and
Statement of Cash Flows, temporary cash investments with
original maturities of three months or less, generally in the
form of commercial paper, certificates of deposit, and
repurchase agreements, are considered to be the equivalent of
cash.
3. The Company owns 28% of the common stock of Allegheny
Generating Company (AGC), and affiliates of the Company own
the remainder. AGC owns an undivided 40% interest, 840
megawatts (MW), in the 2,100 MW pumped-storage hydroelectric
station in Bath County, Virginia, operated by the 60% owner,
Virginia Electric and Power Company, a nonaffiliated utility.
Following is a summary of income statement information for
AGC:
Three Months Ended Six Months Ended
June 30 June 30
1998 1997 1998 1997
(Thousands of Dollars)
Electric operating revenues $19,126 $20,408 $37,730 $40,624
Operation and maintenance
expense 1,542 1,471 2,495 2,756
Depreciation 4,242 4,284 8,468 8,568
Taxes other than income taxes 1,177 1,201 2,337 2,396
Federal income taxes 2,907 3,141 5,772 6,265
Interest charges 3,298 3,917 6,811 7,877
Other income, net (1) (1) (51) (1)
Net income $ 5,961 $ 6,395 $11,898 $12,763
The Company's share of the equity in earnings above was $1.6
million and $1.8 million for the three months ended June 30,
1998 and 1997, respectively, and $3.3 million and $3.6
million for the six months ended June 30, 1998 and 1997,
respectively, and was included in other income, net, on the
Statement of Income.
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4. On April 7, 1997, the Company's parent, Allegheny Power
System, Inc. (now renamed Allegheny Energy, Inc.) and DQE,
Inc. (DQE), parent company of Duquesne Light Company in
Pittsburgh, Pennsylvania, announced that they had agreed to
merge in a tax-free, stock-for-stock transaction.
On March 25, 1998, the Maryland Public Service Commission
(PSC) approved a settlement agreement between Allegheny
Energy, Inc. (Allegheny Energy) and various parties, in which
the PSC indicated its approval of the merger. This action
was requested in connection with the proposed issuance of
Allegheny Energy stock to exchange for DQE stock to complete
the merger.
On July 8, 1998, the City of Pittsburgh reached a settlement
agreement with Allegheny Energy and agreed to support the
merger.
On July 16, 1998, the Public Utilities Commission of Ohio
(PUCO) found that the proposed merger would be in the public
interest. The PUCO also stated that the Midwest ISO is the
regional transmission entity that will best serve the
interests of the Ohio customers of Monongahela Power Company,
the Company's utility affiliate, and will best mitigate the
market power issue.
The Nuclear Regulatory Commission has approved the transfer
of control of the operating licenses for DQE's nuclear
plants. While Duquesne Light Company (Duquesne), principal
subsidiary of DQE, will continue to be the licensee, this
approval was necessary since control of Duquesne will pass
from DQE to Allegheny Energy after the merger.
On July 23, 1998, the Pennsylvania Public Utility Commission
(PUC) approved the Allegheny Energy-DQE merger with
conditions acceptable to Allegheny Energy in response to a
Petition for Reconsideration filed by Allegheny Energy on
June 12, 1998. In its Petition for Reconsideration of a
previous PUC Order, Allegheny Energy reiterated its
commitment to staying in and supporting the Midwest ISO, and
also offered to relinquish some generation in order to
mitigate market power concerns. Allegheny Energy committed
to relinquishing control of the 570 MW Cheswick,
Pennsylvania, generating station through at least June 30,
2000 and, in the event that the Midwest ISO has not
eliminated pancaked transmission rates by June 30, 2000,
Allegheny Energy may be required to divest up to 2,500 MW of
generation, subject to a PUC Order.
In a letter dated July 28, 1998 to Allegheny Energy, DQE
stated that its Board of Directors determined that DQE was
not required to proceed with the merger under present
circumstances, referring to the PUC's Orders of July 23, 1998
(regarding the PUC's approval of the merger described above),
and May 29, 1998 (regarding the restructuring plan of the
Company's Pennsylvania affiliate, West Penn Power Company
(West Penn) described in Note 5 below). DQE took the
position that the findings of both Orders constitute a
material adverse effect under the Agreement and Plan of
Merger and invited Allegheny Energy to agree promptly to
terminate the merger agreement by mutual consent. DQE
asserted that the findings in the PUC Orders will result in a
failure of the conditions to DQE's obligation to consummate
the merger. DQE indicated that if Allegheny Energy was not
amenable to a consensual termination, DQE would terminate the
agreement unilaterally not later than October 5, 1998 if
circumstances did not change sufficiently to remedy the
adverse effects DQE stated were associated with the PUC
Orders. In a letter dated July 30, 1998,
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Allegheny Energy informed DQE that DQE's allegations were
incorrect, that the Orders do not constitute a material
adverse effect, that Allegheny Energy remains committed to
the merger, and that if DQE prevents completion of the
merger, Allegheny Energy will pursue all remedies available
to protect the legal and financial interests of Allegheny
Energy and its shareholders. Allegheny Energy has also
notified DQE that its letter and other actions constitute a
material breach of the merger agreement by DQE.
All of the Company's incremental costs of the merger process
($4.3 million through June 30, 1998) are being deferred. The
accumulated merger costs will be written off by the Company
when the merger occurs, or when it is determined that the
merger will not occur.
5. As required by the Maryland PSC, the Company, on July 1,
1998, filed testimony in Maryland's investigation into
stranded costs, price protection, and unbundled rates. The
filing also requested a surcharge to recover the cost of the
Warrior Run cogeneration project which is scheduled to
commence production on October 1, 1999. Hearings are
scheduled to begin in March 1999. A second PSC proceeding is
planned to begin examining market power protective measures
in December 1999.
In December 1996, Pennsylvania enacted the Electricity
Generation Customer Choice and Competition Act (Customer
Choice Act) to restructure the electric industry in
Pennsylvania to create retail access to a competitive
electric energy generation market. The Company's
Pennsylvania affiliate, West Penn, is subject to this Act.
On August 1, 1997, West Penn filed with the PUC a
comprehensive restructuring plan to implement full customer
choice of electric generation suppliers as required by the
Customer Choice Act. The filing included a plan for recovery
of stranded costs through a Competitive Transition Charge
(CTC).
On May 29, 1998, West Penn received a final order from the
PUC denying full recovery of its stranded cost claim. The
Order authorized recovery of $524 million in stranded costs,
with return, over the 1999 through 2005 period, of the
approximately $1.2 billion available for recovery under the
capped rates mandated by the Customer Choice Act.
On June 26, 1998, the PUC denied a request by West Penn for
reconsideration of the May 29, 1998 PUC Order on West Penn's
restructuring plan. Under the reconsideration Order, West
Penn would be allowed to collect $525 million ($.5 million
more than the previous Order) in stranded costs, with a
return, over seven years, starting in January 1999, through
the CTC. Although in its restructuring application, West
Penn had listed $1.6 billion in stranded costs, because of
capped rates, West Penn would be limited to $1.2 billion in
stranded cost recovery under the Customer Choice Act.
Stranded costs are costs incurred under a regulated
environment, which are not expected to be recoverable in a
competitive market. Actual recovery of such costs will
depend upon the market prices for electricity in future
periods and the number of West Penn customers who choose
other generation suppliers. The PUC Order on West Penn's
restructuring plan assumed significantly higher electricity
prices in future years than Allegheny Energy believed were
appropriate.
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Allegheny Energy believes that the $525 million of stranded
costs recommended for recovery is contrary to legal
requirements and does not adequately reflect the potential
effects of competition on West Penn. On June 26, 1998, West
Penn filed a formal appeal in state court and an action in
federal court challenging the PUC's restructuring Order. On
July 23, 1998, West Penn also filed in the Commonwealth Court
of Pennsylvania a petition for a stay of the two-thirds, one-
third phase-in schedule ordered by the PUC. On August 5,
1998, West Penn withdrew its petition for stay without
prejudice based on a PUC agreement to offer settlement
discussions on issues related to the PUC's restructuring
Order.
As a result of the PUC restructuring Order, West Penn has
determined that it is required to discontinue the application
of Statement of Financial Accounting Standards (SFAS) No. 71
for electric generation operations and to adopt SFAS No. 101,
"Accounting for the Discontinuation of Application of SFAS
No. 71". In doing so, West Penn has also determined that
under the provisions of SFAS No. 101 an extraordinary charge
of $450.6 million ($265.4 million after taxes) is required to
reflect a write-off of disallowances in the PUC's Order. The
write-off, recorded in June 1998 by West Penn, reflects
adverse power purchase commitments and deferred costs that
are not recoverable from customers under the PUC's Order.
6. In June 1998, the Financial Accounting Standards Board issued
SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities," to establish accounting and reporting
standards for derivatives. The new standard requires
recognizing all derivatives as either assets or liabilities
on the balance sheet at their fair value and specifies the
accounting for changes in fair value depending upon the
intended use of the derivative. The new standard is effective
for fiscal years beginning after June 15, 1999. The Company
expects to adopt SFAS No. 133 in the first quarter of 2000.
The Company is in the process of evaluating the impact of
SFAS No. 133.
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THE POTOMAC EDISON COMPANY
Management's Discussion and Analysis of Financial Condition
and Results of Operations
COMPARISON OF SECOND QUARTER AND SIX MONTHS ENDED JUNE 30, 1998
WITH SECOND QUARTER AND SIX MONTHS ENDED JUNE 30, 1997
The Notes to Financial Statements and Management's
Discussion and Analysis of Financial Condition and Results of
Operations in the Company's Annual Report on Form 10-K for the
year ended December 31, 1997 should be read in conjunction with
the following Management's Discussion and Analysis information.
Factors That May Affect Future Results
This management's discussion and analysis of financial
condition and results of operations contains forecast information
items that are "forward-looking statements" as defined in the
Private Securities Litigation Reform Act of 1995. These include
statements with respect to deregulation activities and movements
toward competition in states served by the Company and the DQE,
Inc. (DQE) merger as well as results of operations. All such
forward-looking information is necessarily only estimated. There
can be no assurance that actual results will not materially
differ from expectations. Actual results have varied materially
and unpredictably from past expectations.
Factors that could cause actual results to differ
materially include, among other matters, electric utility
restructuring, including the ongoing state and federal
activities; potential Year 2000 operation problems; developments
in the legislative, regulatory, and competitive environments in
which the Company operates, including regulatory proceedings
affecting rates charged by the Company; environmental legislative
and regulatory changes; future economic conditions; developments
relating to the proposed merger with DQE, including expenses that
may be incurred in litigation if DQE seeks to terminate the
merger agreement; and other circumstances that could affect
anticipated revenues and costs such as significant volatility in
the market price of wholesale power, unscheduled maintenance or
repair requirements, weather, and compliance with laws and
regulations.
Significant Events in the First Six Months of 1998
* Merger with DQE
In a letter dated July 28, 1998 to Allegheny Energy, DQE
stated that its Board of Directors determined that DQE was not
required to proceed with the merger under present circumstances,
referring to the Pennsylvania Public Utility Commission (PUC)
Orders of July 23, 1998 and May 29, 1998. See Notes 4 and 5 to
the financial statements for more information about these Orders.
DQE took the position that the findings of both Orders constitute
a material adverse effect under the Agreement and Plan of Merger,
and invited Allegheny Energy to agree promptly to terminate the
merger agreement by mutual consent.
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DQE asserted that the findings in the PUC Orders will result in a
failure of the conditions to DQE's obligation to consummate the
merger. DQE indicated that if Allegheny Energy was not amenable
to a consensual termination, DQE would terminate the agreement
unilaterally not later than October 5, 1998 if circumstances did
not change sufficiently to remedy the adverse effects DQE stated
were associated with the PUC Orders. In a letter dated July 30,
1998, Allegheny Energy informed DQE that DQE's allegations were
incorrect, that the Orders do not constitute a material adverse
effect, that Allegheny Energy remains committed to the merger,
and that if DQE prevents completion of the merger, Allegheny
Energy will pursue all remedies available to protect the legal
and financial interests of Allegheny Energy and its shareholders.
Allegheny Energy has also notified DQE that its letter and other
actions constitute a material breach of the merger agreement by
DQE. Allegheny Energy believes that DQE's basis for seeking to
terminate the merger is without merit. Accordingly, Allegheny
Energy is continuing to seek the remaining regulatory approvals
from the Federal Energy Regulatory Commission (FERC), the
Department of Justice, and the Securities and Exchange
Commission. The Company cannot predict the outcome of the
requested approvals or of the differences between Allegheny
Energy and DQE.
* Maryland Settlement and Deregulation
After substantial negotiations, the Company reached a
settlement agreement with various parties on the Office of
People's Counsel's (OPC) petition for a reduction in the
Company's Maryland rates. Under the terms of the agreement, the
Company will increase its rates about 3% in each of the years
1999, 2000, and 2001 (about $11 million each year). The
increases reflect the net effect of a rate increase of about $60
million for recovery of a power purchase commitment for energy
from AES Corporation's "Warrior Run" generation project beginning
October 1, 1999, offset by rate reductions reflecting Maryland's
share of the Company's merger savings (about $4.4 million
annually) when Allegheny Energy merges with DQE, and other rate
reductions to reduce the Company's "excess earnings" alleged by
OPC. The net effect of the agreement over the 1999-2001 time
frame is expected to result in a pre-tax income reduction of
$16.4 million in 1999, $22.4 million in 2000, and $26.4 million
in 2001. In addition, the settlement requires that the Company
share, on a 50% customer, 50% shareholder basis, earnings above a
threshold return on equity (ROE) level of 11.4% for 1999-2001.
This sharing will occur through an after-the-fact true-up
conducted after each calendar year is completed. The settlement
agreement was filed with the Maryland Public Service Commission
on July 30, 1998. "Warrior Run" is a cogeneration project being
built by AES Corporation in western Maryland. The Company is
required to purchase the project's energy at above-market prices
pursuant to the requirements of the Public Utility Regulatory
Policies Act of 1978 (PURPA).
On July 1, 1998, the Company filed testimony in
Maryland's investigation into stranded costs, price protection,
and unbundled rates. See Note 5 to the financial statements for
more information regarding the Maryland filing.
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* Pennsylvania Deregulation
On May 29, 1998, West Penn Power Company (West Penn), the
Company's Pennsylvania affiliate, received a final order from the
PUC denying full recovery of its stranded cost claim. The Order
authorized recovery of $524 million in stranded costs, with
return, over the 1999 through 2005 period, of the approximately
$1.2 billion available for recovery under the capped rates
mandated by the Customer Choice Act.
On June 26, 1998, the PUC denied a request by West Penn
for reconsideration of the May 29, 1998 PUC Order on West Penn's
restructuring plan. Under the reconsideration Order, West Penn
would be allowed to collect $525 million ($.5 million more than
the previous Order) in stranded costs, with a return over seven
years, starting in January 1999, through the Competitive
Transition Charge (CTC). Although in its restructuring
application, West Penn had listed $1.6 billion in stranded costs,
because of capped rates, West Penn would be limited to $1.2
billion in stranded cost recovery under the Customer Choice Act.
Stranded costs are costs incurred under a regulated environment
which are not expected to be recoverable in a competitive market.
Actual recovery of such costs will depend upon the market prices
for electricity in future periods and the number of West Penn
customers who choose other generation suppliers. The PUC Order
on West Penn's restructuring plan assumed significantly higher
electricity prices in future years than Allegheny Energy believed
were appropriate.
Allegheny Energy believes that the $525 million of
stranded costs recommended for recovery is contrary to legal
requirements and does not adequately reflect the potential
effects of competition on West Penn. On June 26, 1998, West Penn
filed a formal appeal in state court and an action in federal
court challenging the PUC's restructuring Order. On July 23,
1998, West Penn also filed in the Commonwealth Court of
Pennsylvania a petition for a stay of the two-thirds, one-third
phase-in schedule ordered by the PUC. On August 5, 1998, West
Penn withdrew its petition for stay without prejudice based on a
PUC agreement to offer settlement discussions on issues related
to the PUC's restructuring Order. Allegheny Energy cannot
predict the outcome of settlement discussions or the related
legal proceedings.
* Trading Activities
In June and July 1998, certain events combined to produce
very significant volatility in the spot prices for electricity at
the wholesale level. These events included extremely hot weather
and Midwest generation unit outages and transmission constraints.
Wholesale prices for electricity rose from a normal range of from
$25-$40 per megawatt-hour (mWh) to as high as $3,500-$7,000 per
mWh. The costs of purchased power and revenues from sales to
power marketers and other utilities, including transmission
services, are currently recovered from or credited to customers
under fuel and energy cost recovery procedures. The impact to
the fuel and energy cost recovery clauses, either positively or
negatively, depends on whether the Company is a net buyer or
seller of electricity during such periods. The impact of such
price volatility in June 1998 was insignificant to the Company.
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Review of Operations
EARNINGS SUMMARY
Net income for the second quarter of 1998 was $20.5
million compared with $18.4 million in the corresponding 1997
period. For the first six months of 1998, net income was $48.4
million compared with $46.1 million for the corresponding 1997
period. The increase in the second quarter is primarily due to a
12.8% and 8.2% increase in kilowatt-hour (kWh) sales to
commercial and industrial customers, respectively.
The increase in year-to-date net income was also due to
increases in kWh sales to commercial and industrial customers of
7.2% and 5.3%, respectively. KWh sales to residential customers,
however, decreased 1.5% in this period primarily due to mild
winter weather in 1998. The 1998 winter was 11% warmer than 1997
and 22% warmer than normal as measured by heating degree days and
was the warmest in more than 100 years.
SALES AND REVENUES
Percentage changes in revenues and kWh sales by major
retail customer classes were:
Change from Prior Periods
Three Months Ended Six Months Ended
June 30 June 30
Revenues kWh Revenues kWh
Residential (.5)% (.6)% (1.0)% (1.5)%
Commercial 12.9 12.8 6.4 7.2
Industrial 4.8 8.2 4.3 5.3
Total 4.3% 6.2% 2.2% 3.1%
Residential kWh sales, which are more weather sensitive
than the other classes, decreased 1.5% in the six months ended
period due primarily to changes in customer usage because of
weather conditions. The 1998 first quarter winter weather was
11% warmer than 1997 and 22% warmer than normal as measured by
heating degree days. The increase in commercial kWh sales for
the three and six months ended periods reflects increased usage
as well as growth in the number of customers. The increase in
industrial kWh sales in both periods reflects increased sales to
paper and printing customers and to the Eastalco aluminum
reduction plant, and generally reflects continued economic growth
in the service territory.
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The changes in revenues from sales to residential,
commercial, and industrial customers resulted from the following:
Change from Prior Periods
Three Months Ended Six Months Ended
June 30 June 30
(Millions of Dollars)
Fuel clauses $3.1 $4.3
All other 3.4 2.9
Net change in retail
revenues $6.5 $7.2
Revenues reflect not only the changes in kWh sales, but
also any changes in revenues from fuel and energy cost adjustment
clauses (fuel clauses) which have little effect on net income
because increases and decreases in fuel and purchased power costs
and sales of transmission services and bulk power are passed on
to customers by adjustment of customer bills through fuel
clauses.
All other is the net effect of kWh sales changes due to
changes in customer usage (primarily weather for residential
customers), growth in the number of customers, and changes in
pricing other than changes in general tariff and fuel clause
rates. The increase in the three and six months ended periods
all other retail revenues was primarily the result of customer
usage.
Wholesale and other revenues were as follows:
Three Months Ended Six Months Ended
June 30 June 30
1998 1997 1998 1997
(Millions of Dollars)
Wholesale customers $ 5.8 $6.0 $12.7 $13.8
Affiliated companies 2.7 2.6 5.3 4.4
Street lighting and other 1.8 .4 3.3 1.3
Total wholesale and other
revenues $10.3 $9.0 $21.3 $19.5
Wholesale customers are cooperatives and municipalities
that own their own distribution systems and buy all or part of
their bulk power needs from the Company under regulation by the
FERC. Competition in the wholesale market for electricity was
initiated by the National Energy Policy Act of 1992 (EPACT),
which permits wholesale generators, utility-owned and otherwise,
and wholesale customers to request from owners of bulk power
transmission facilities a commitment to supply transmission
services. Five-year contracts have been signed (one in 1997 with
an expiration date in 2002 with estimated annual revenues of $3
million, and four in 1998 with expiration dates in 2003 with
estimated annual revenues of $19 million) with the Company's
wholesale customers allowing the Company to continue as their
wholesale supplier. The decrease in wholesale revenues in 1998
was primarily due to the mild 1998 winter as mentioned above.
<PAGE>
- 15 -
Revenues from affiliated companies represent sales of
energy and intercompany allocations of generation spinning
reserves and transmission services pursuant to a power supply
agreement among the Company and the other regulated utility
subsidiaries of Allegheny Energy. The increase in such revenues
in the three and six months ended June 30, 1998 resulted
primarily from an increase in the allocation of transmission
services revenues to the Company.
The increases in street lighting and other revenues in
the quarter and year-to-date periods ended June 30, 1998 were
primarily due to an increase in rental revenues associated with
company-owned facilities.
Bulk power transactions consist of sales of power to
power marketers and other utilities. Revenues from bulk power
transactions consist of the following items:
Three Months Ended Six Months Ended
June 30 June 30
1998 1997 1998 1997
(Millions of Dollars)
Revenues:
Transmission services to
nonaffiliated companies $ 3.5 $2.9 $ 6.3 $ 7.1
Bulk power 6.5 2.3 7.9 4.1
Total bulk power trans-
actions, net $10.0 $5.2 $14.2 $11.2
Revenues from bulk power sales increased in the second
quarter and in the first six months of 1998 due to increased
sales of energy which occurred primarily in the month of June as
a result of a heat wave which increased the demand and prices for
energy.
OPERATING EXPENSES
Fuel expenses for the three and six months ended June 30,
1998 increased 7.3% and 3.8%, respectively, due to an increase in
kWh's generated. Fuel expenses are primarily subject to deferred
power cost accounting procedures with the result that changes in
fuel expenses have little effect on net income.
<PAGE>
- 16 -
Purchased power and exchanges, net represents power
purchases from and exchanges with nonaffiliated utilities,
capacity charges paid to Allegheny Generating Company (AGC), an
affiliate partially owned by the Company, and other transactions
with affiliates made pursuant to a power supply agreement whereby
each company uses the most economical generation available in the
Allegheny Energy System at any given time, and consists of the
following items:
Three Months Ended Six Months Ended
June 30 June 30
1998 1997 1998 1997
(Millions of Dollars)
Nonaffiliated transactions:
Purchased power $ 2.1 $ 2.4 $ 4.8 $ 5.1
Power exchanges, net (.6) (.5) .7 .9
Affiliated transactions:
AGC capacity charges 6.1 6.7 12.3 13.3
Other affiliated capacity
Charges 10.9 12.9 22.8 25.6
Energy and spinning
reserve charges 11.0 10.5 24.8 24.7
Purchased power and
exchanges, net $29.5 $32.0 $65.4 $69.6
The AES Warrior Run PURPA power station project in the
Company's Maryland jurisdiction is scheduled to commence
generation in 1999. Because of the high cost of this energy, the
Company unsuccessfully sought a buyout or restructuring of the
existing contract to reduce the cost of power purchases ($60
million or more annually) and to prevent the need for increases
in the Company's rates in Maryland. On July 30, 1998, a
settlement agreement was filed with the Maryland PSC. See page
11 for further information on the agreement.
The increase in other operation expenses for the three
months ended June 1998 was due primarily to increased allowances
for uncollectible accounts ($.3 million), rent expense ($.5
million) and expenses related to competition in Maryland ($.3
million). The increase for the six months ended June 1998 was
similarly due primarily to increased allowances for uncollectible
accounts ($.6 million), rent expense ($.8 million), and expenses
related to competition in Maryland ($.3 million).
Maintenance expenses decreased $2.8 million and $3.7
million for the second quarter and year-to-date June 30, 1998,
respectively, due primarily to reduced expenses achieved through
restructuring efforts and other cost controls. Maintenance
expenses represent costs incurred to maintain the power stations,
the transmission and distribution (T&D) system, and general
plant, and reflect routine maintenance of equipment and rights-of-
way as well as planned major repairs and unplanned expenditures,
primarily from forced outages at the power stations and periodic
storm damage on the T&D system. Variations in maintenance
expense result primarily from unplanned events and planned major
projects, which vary in timing and magnitude depending upon the
length of time equipment has been in service without a major
overhaul and the amount of work found necessary when the
equipment is dismantled.
Depreciation expense in the three and six months ended
June 1998 increased primarily due to additions to electric plant.
<PAGE>
- 17 -
The increases in federal and state income taxes in the
second quarter and six months ended June 30, 1998, resulted
primarily from increases in income before taxes.
Other interest expense reflects changes in the levels of
short-term debt maintained by the Company throughout the year, as
well as the associated interest rates.
Financial Condition
The Company's discussion on Financial Condition,
Requirements, and Resources and Significant Continuing Issues in
its Annual Report on Form 10-K for the year ended December 31,
1997 should be read in conjunction with the following
information.
In the normal course of business, the Company is subject
to various contingencies and uncertainties relating to its
operations and construction programs, including legal actions and
regulations and uncertainties related to environmental matters.
See Notes 4 and 5 to the Financial Statements for information
about merger activities, the Pennsylvania Customer Choice Act,
and the Maryland activities relating to the deregulation of
electricity generation.
* Risk Management
The Company and its affiliates manage the risk exposure
associated with contracts they write for the purchase and/or sale
of electricity for receipt or delivery at future dates. Such
management is done in accordance with a formal risk management
policy adopted by the Board of Directors and monitored by an
Exposure Management Committee of senior management. The policy
requires continuous monitoring, reporting, and stress testing of
all open positions for conformity to policies which limit value
at risk and market risk associated with the credit standing of
trading counterparties. Such credit standings must be investment
grade or better, or be guaranteed by a parent company with such a
credit standing for all over-the-counter instruments.
At June 30, 1998, the trading books of the Company and
its affiliates consisted primarily of physical contracts with
fixed pricing. Most contracts were fixed-priced, forward-
purchase and/or sale contracts which require settlement by
physical delivery of electricity. During 1998, the Company and
its affiliates also entered into option contracts which, if
exercised, were settled with physical delivery of electricity.
These transactions result in market risk which occurs when the
market price of a particular obligation or entitlement varies
from the contract price. As the Company continues to develop its
power marketing and trading business, its exposure to volatility
in the price of electricity and other energy commodities may
increase within approved policy limits.
<PAGE>
- 18 -
* Year 2000 Readiness
As the Year 2000 approaches, most organizations,
including the Company, could experience serious problems related
to software and various equipment with embedded chips which may
not properly recognize calendar dates. To minimize such problems,
the Company and its affiliates in the Allegheny Energy System
(the System) are proceeding with a comprehensive effort to
continue operations without significant problems in the Year 2000
(Y2K) and beyond. An Executive Task Force is coordinating the
efforts of 21 separate Y2K Teams, representing all business and
support units in the System.
The System has segmented the Y2K problem into the
following components:
* Computer software
* Embedded chips in various equipment
* Vendors and other organizations on which the System
relies for critical materials and services.
The System's effort for each of these three components
includes assessment of the problem areas, remediation, testing
and contingency plans for critical functions for which
remediation and testing are not possible or which do not provide
reasonable assurance.
The Company has expended significant time and money over
the past several years on upgrading and replacing its large and
complex computer systems and software to achieve greater
efficiency as well as Y2K readiness. As a result, the Company
expects these systems to achieve a state of Y2K readiness on or
about March 31, 1999, subject to continuing review and testing.
Various equipment used by the System includes thousands
of embedded chips. Most are not date sensitive, but identifying
those which are, and which are critical to operations, is a labor
intensive task. Identification, remediation, and testing in many
cases require the assistance of the original equipment
manufacturers. Even they frequently cannot state with certainty
if the chips they used are date sensitive. The System's review
calls for the inventory and assessment of suspect embedded chips
in critical systems to be completed by December 31, 1998,
remediation initiated as needs are identified, with 1999 to
complete remediation and testing.
Integrated electric utilities are uniquely reliant on
each other to avoid, in a worst case situation, cascading failure
of the entire electrical system. The System is working with the
Edison Electric Institute (EEI), the Electric Power Research
Institute (EPRI), the North American Electric Reliability Council
(NERC), and the East Central Area Reliability Agreement group
(ECAR) to capitalize on industry-wide experiences and to
participate in industry-wide testing and contingency planning.
The effort with regard to vendors and other organizations is to
obtain reasonable assurance of their readiness to conduct
operations at the Year 2000 and beyond and, where reasonable
assurance is questionable, to develop contingency plans. Of
particular concern are telecommunications systems which are
integral to the System's electricity production and distribution
operations. While the System will develop contingency plans for
critical telecommunication needs, there can be no assurance that
the contingency plans could cope with a significant failure of
major telecommunication systems.
<PAGE>
- 19 -
The Company is aware of the importance of electricity to
its service territory and its customers and is using its best
efforts to avoid any serious Y2K problems. Despite the System's
best efforts, including working with internal resources, external
vendors, and industry associations, the Company cannot guarantee
that it will be able to conduct all of its operations without Y2K
interruptions. To the extent that any Y2K problem may be
encountered, the Company is committed to resolution as
expeditiously as possible to minimize the effect.
Expenditures for Y2K readiness are not expected to have a
material effect on the Company's results of operations or
financial position primarily because of the significant time and
money expended over the past several years on upgrading and
replacing its large mainframe computer systems and software.
While the remaining Y2K work is significant, it primarily
represents an internal labor intensive effort of assessment,
remediation, and component testing for noncompliant embedded
chips in equipment, and a substantial labor intensive effort of
multiple systems testing, documentation, and working with other
parties. While outside contractors and equipment vendors will be
employed for some of the work, the Company believes it must rely
on System employees for most of the effort because of their
experience with systems and equipment. The Company currently
estimates that its incremental expenditures for the remaining Y2K
effort will not exceed $4 million.
The descriptions herein of the elements of the Company's
Y2K effort are forward-looking statements as defined in the
Private Securities Litigation Reform Act of 1995. Of necessity,
this effort is based on estimates of assessment, remediation,
testing and contingency planning activities and dates for
perceived problems not yet identified. There can be no assurance
that actual results will not materially differ from expectations.
* Environmental Issues
The Company previously reported that the EPA had
identified the Company and its regulated affiliates and
approximately 875 others as potentially responsible parties in a
Superfund site subject to cleanup. A final determination has not
been made for the Company's share of the remediation costs based
on the amount of materials sent to the site. The Company has
also been named as a defendant along with multiple other
affiliated and nonaffiliated defendants in pending asbestos cases
involving one or more plaintiffs. The Company believes that
provisions for liabilities and insurance recoveries are such that
final resolution of these claims will not have a material effect
on its financial position.
* Electric Energy Competition
Allegheny Energy is working actively within its states to
advance customer choice. However, Allegheny Energy believes that
federal legislation is necessary to ensure that electric
restructuring is implemented consistently across state and
regional boundaries so that all electric customers have an equal
opportunity to benefit from competition and customer choice by a
date certain. Federal legislation is also needed to remove
barriers to competition, including the repeal of both the Public
Utility Holding Company Act of 1935 and PURPA. Although several
restructuring bills were introduced in the House and Senate in
1998, Congress is not expected to move legislation on
restructuring this year.
<PAGE>
- 20 -
In addition to deregulation activities in Maryland, the
Company serves customers in West Virginia and Virginia which are
exploring the move toward competition and deregulation.
The West Virginia Legislature passed a House Bill on
March 14, 1998 which sets the stage for the restructuring of the
electric utility industry in West Virginia. The House Bill
directed the West Virginia Public Service Commission (West
Virginia PSC) to determine if deregulation is in the best
interests of the state and, if so, to develop a transition plan.
It also set up a task force of all interested parties to
participate in the plan development. The West Virginia PSC has
been conducting meetings of the Task Force on Restructuring over
the summer to examine if competition is in the best interest of
the state and, if so, to develop a transition plan. All
interested parties have participated in the process which is
nearing the end of its official schedule with little apparent
progress concerning a defined plan for restructuring. The
deadline to file a consensus workshop report and comments
regarding the Commission's public interest determination is
August 26, 1998. The Commission also announced a series of five
public hearings in August and September to allow for broader
public input into the process. Evidentiary hearings are
scheduled for September 29, 1998 to address utility unbundling
and stranded cost filings.
In early March 1998, the Virginia Senate joined the House
of Delegates in approving a timetable for restructuring the
state's electric utility industry to allow retail competition.
The legislation will give Virginians choice of their electric
power suppliers beginning on January 1, 2004. The details will
be worked out over the coming year by a special Senate-House
subcommittee that has been studying restructuring for two years.
The joint legislative subcommittee studying utility restructuring
has held a series of meetings to examine the issues associated
with restructuring. Two subcommittees have been established to
examine structure and transmission issues and stranded costs.
All interested parties have been invited to participate in the
process. The Virginia State Corporation Commission (SCC) ordered
two utilities, but not the Company, to develop retail pilot
programs. Those utilities have until November 1, 1998 to develop
and submit their retail pilot programs to the SCC.
<PAGE>
- 21 -
THE POTOMAC EDISON COMPANY
Part II - Other Information to Form 10-Q
for Quarter Ended June 30, 1998
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits:
(27) Financial Data Schedule
(b) No reports on Form 8-K were filed on behalf of the
Company for the quarter ended June 30, 1998.
Signature
Pursuant to the requirements of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be
signed on its behalf by the undersigned thereunto duly
authorized.
THE POTOMAC EDISON COMPANY
/s/ T. J. KLOC
T. J. Kloc, Controller
(Chief Accounting Officer)
August 14, 1998
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